Gaseous seal injection in a wellbore

ABSTRACT

A method for treating a well includes flowing a sealant heated to a gaseous phase to cement disposed in an annulus of a wellbore, where the annulus is formed between a casing installed in the wellbore and a cylindrical wall radially outward of the casing. The cement includes a fluid loss opening formed over time. The method includes flowing the sealant in gaseous phase through the fluid loss opening in the cement of the annulus, and cooling the sealant in the gaseous phase into a phase transition of the sealant. The phase transition includes a deposition of the sealant from the gaseous phase to a solid phase or a condensation of the sealant from the gaseous phase to a liquid phase. Further, the sealant seals the fluid loss opening in response to cooling the sealant.

TECHNICAL FIELD

This disclosure relates to well treatment, and more particularly to plugging and sealing a fluid opening through tight micro-cracks and channels in cement inside a casing-casing-annulus of oil and gas wells.

BACKGROUND

Well control fluid can be used in wellbore sealing operations, wellbore testing operations, or other downhole-type plugging operations to reduce permeability of a downhole wall or surface in a wellbore or cemented casing, for example, by plugging cracks or fractures in the wellbore. Sometimes, well control fluid is a liquid gel or solid material that is injected into an annulus of a wellbore to an annulus location to plug and seal cracks or other fractures in the annulus.

SUMMARY

This disclosure describes well treatment systems for treating a well, for example, for plugging and sealing cracks or fractures in a cemented annulus of a wellbore.

Certain aspects of the disclosure encompass a method for treating a well. The method includes flowing a sealant heated to a gaseous phase to cement disposed in an annulus of a wellbore, the annulus formed between a casing installed in the wellbore and a cylindrical wall radially outward of the casing, where the cement includes a fluid loss opening formed over time in the cement. The method further includes flowing the sealant in gaseous phase through the fluid loss opening in the cement of the annulus, and in response to flowing the sealant through the fluid loss opening, cooling the sealant in the gaseous phase into a phase transition of the sealant, the phase transition comprising at least one of a deposition of the sealant from the gaseous phase to a solid phase or a condensation of the sealant from the gaseous phase to a liquid phase. The method further includes sealing the fluid loss opening with the sealant in response to cooling the sealant.

This, and other aspects, can include one or more of the following features. The method can include heating the sealant in a heating chamber and converting the sealant to the gaseous phase. Converting the sealant to the gaseous phase can include at least one of a sublimation of the sealant from solid phase to gaseous phase or an evaporation of the sealant from liquid phase to gaseous phase. The heating chamber can include an electric heating chamber, and heating the sealant can include heating the sealant in the electric heating chamber. The method can include purging the heating chamber using inert gas chambers fluidly connected to the heating chamber. Flowing the sealant to the cement disposed in the annulus of the wellbore can include pumping the sealant into the cement with a compressor. Flowing the sealant to the cement disposed in the annulus of the wellbore can include continuously flowing the sealant in the gaseous phase into the cement until a positive pressure test of the annulus occurs. Flowing the sealant to the cement disposed in the annulus of the wellbore can include flowing the sealant in the gaseous phase downhole through the annulus from a tophole surface of the wellbore. The fluid loss opening can include a crack in the cement of the wellbore, and sealing the fluid loss opening with the sealant can include pressure sealing the crack in the cement of the wellbore with the sealant. The sealant in gaseous phase can include an inert gas.

Certain aspects of the disclosure include a well treatment system for treating a well, the well treatment system including a heating chamber fluidly connected to an annulus of a wellbore, the heating chamber to heat a sealant to a gaseous phase. The sealant in gaseous phase is to engage a fluid loss opening in cement disposed in the annulus of the wellbore and, upon cooling the sealant, transition phases from the gaseous phase to at least one of a liquid phase or a solid phase and plug the fluid loss opening.

This, and other aspects, can include one or more of the following features. The well treatment system can include a gas compressor to flow the sealant in gaseous phase from the heating chamber to the annulus of the wellbore. The well treatment system can include a casing spool flange to receive a flow of the sealant from the heating chamber and direct the flow of sealant into the annulus of the wellbore. The fluid loss opening in the cement disposed in the annulus of the wellbore can include a crack in the cement. The crack in the cement of the annulus can include a micro-crack in the cement. The heating chamber can include an electric heating chamber. The well treatment system can include inert gas chambers fluidly connected to the heating chamber to purge the heating chamber. The annulus can be formed between a casing installed in the wellbore and a cylindrical wall radially outward of the casing. The cylindrical wall can include a second casing installed in the wellbore radially outward from the first-mentioned casing or an inner wall of the wellbore.

Certain aspects of the disclosure encompass a method for treating a well. The method includes flowing a sealing composition in a gaseous phase through a fluid loss opening in a well, cooling the sealing composition into a phase transition of the sealing composition, the phase transition including at least one of a deposition of the sealing composition from the gaseous phase to a solid phase or a condensation of the sealing composition from the gaseous phase to a liquid phase, and, in response to cooling the sealing composition into the phase transition of the sealing composition, sealing the fluid loss opening with the sealing composition.

This, and other aspects, can include one or more of the following features. The fluid loss opening can include an opening in cement disposed in a wellbore annulus of the well. The method can include heating the sealing composition in a heating chamber and converting the sealing composition to the gaseous phase prior to flowing the sealing composition in the gaseous phase through the fluid loss opening in the well.

The details of one or more implementations of the subject matter described in this disclosure are set forth in the accompanying drawings and the description. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic partial cross-sectional view of an example well system including a well treatment system.

FIG. 2 is a schematic view of an example well treatment system.

FIGS. 3 and 4 are flowcharts showing example processes for treating a wellbore.

Like reference numbers and designations in the various drawings indicate like elements.

DETAILED DESCRIPTION

This disclosure describes systems and methods for sealing cracks, fractures, or other openings in a wellbore, for example, in a cemented annulus adjacent a casing of the wellbore. A well treatment system provides a sealant in gaseous form to the opening or openings, and the sealant cools into a phase transition from a gaseous phase to a solid phase or liquid phase to plug and seal the opening or openings. The present disclosure describes sealing micro-cracks, which include cracks or other openings that are too small for conventional liquid or solid sealants to fill. Many wellbores include a casing that lines at least a portion of a length of the wellbore, and cement that fills an annulus formed between the casing and another outer cylindrical wall, such as the wellbore wall or another casing. Since cement is prone to cracking and wear over time, migration of well fluid or formation fluid (or both) can occur through fluid loss openings in the cement, such as through cracks and micro-channels in the cement that communicate to a fluid opening zone. The present disclosure describes the injection of a gaseous sealant into the cracks and micro-channels and other fluid loss openings, and the phase transition of the sealant to a solid or liquid form while the sealant is disposed within the fluid loss openings, thereby plugging and sealing the fluid loss openings from fluid loss or other fluid migration. While the present disclosure describes micro-cracks or other fluid loss openings in the cement of an annulus of a wellbore, fluid loss openings can be present in other areas of a wellbore. For example, a fluid loss opening can be present in open-hole portions of a wellbore, in a downhole-type well tool disposed within a wellbore, in the wellbore casing, a combination of these, or other surfaces within a wellbore. The present disclosure is applicable to the sealing of these additional fluid loss openings, as well.

In conventional sealing systems, a liquid-phase or solid-phase sealing fluid, such as a gel fluid or cement slurry, is pumped to a location of a crack or other fluid loss opening of a wellbore to seal the opening. Fluid loss openings can include cracks, fractures, perforations, or other openings in the components in a wellbore, such as a casing, cement in a wellbore annulus, a well tool, a formation, or other components of a well system. However, in some instances, flowing sealant in its liquid phase or solid phase to the fluid loss opening can be difficult or impossible due to a lack of permeability of the medium in which the opening is formed. In contrast, flowing the sealant in gaseous form is easier, as the sealant in gaseous phase is able to flow through mediums with a permeability that would otherwise restrict liquid or solid phase sealants from flowing through it. For example, liquid-phase or solid-phase sealing fluid is too large to penetrate and seal some small-scale (for example, micro-sized) fluid loss openings. For example, micro-cracks can include a dimension of ten to fifty micrometers. Cement has a natural porosity but limited permeability, unless micro-cracks or larger cracks develop and interconnect, for example, through the life cycle of an oil or gas well and cause pressure communication from a high pressure formation to a surface wellhead. In the present disclosure, a sealing composition is heated to a gaseous phase, for example, in a heating chamber at a surface of a wellbore, then pumped to the location of a fluid loss opening(s). The sealing composition in its gaseous phase can enter into the fluid loss opening, including small-scale openings and micro-cracks, then cool to its solid phase or its liquid phase to plug the fluid loss opening. The sealant in gaseous phase can enter smaller openings, like micro-cracks, that a sealant in liquid phase or solid phase cannot fit into or flow into. For example, in a cement annulus, a sealant can flow into and seal the fluid communication channel or channels created by micro-cracks formed in the cement. The sealant, or sealing composition, is described in more detail later. Sealing micro-cracks and other fluid loss openings in the cement of a wellbore annulus can reduce or eliminate unwanted fluid flow in the annulus, such as oil or gas flow, and reduce or eliminate pressure buildup in the annulus and a corresponding wellhead. The sealing of micro-cracks and other fluid loss openings in the cement can help reduce or eliminate safety concerns of having high pressures at a wellhead and potential crossflow behind the casing of a well.

FIG. 1 is a schematic partial cross-sectional side view of an example well system 100 that includes a substantially cylindrical wellbore 102 extending from a wellhead 104 at a surface 105 downward into the Earth into one or more subterranean zones of interest. In the example well system, the one or more subterranean zones of interest include a first subterranean zone 106 and a second subterranean zone 107. The well system 100 includes a vertical well, with the wellbore 102 extending substantially vertically from the surface 105 to the first subterranean zone 106 and the second subterranean zone 107. The concepts described here, however, are applicable to many different configurations of wells, including vertical, horizontal, slanted, or otherwise deviated wells.

After some or all of the wellbore 102 is drilled, a portion of the wellbore 102 extending from the wellhead 104 to the subterranean zone 106 or zone 107 can be lined with lengths of tubing, called casing or liner. The wellbore 102 can be drilled in stages, the casing may be installed between stages, and cementing operations can be performed to inject cement in stages between the casing and a cylindrical wall positioned radially outward from the casing. The cylindrical wall can be an inner wall of the wellbore 102 such that the cement is disposed between the casing and the wellbore wall, the cylindrical wall can be a second casing such that the cement is disposed between the two tubular casings, or the cylindrical wall can be a different substantially tubular or cylindrical surface radially outward of the casing. In the example well system 100 of FIG. 1, the system 100 includes a first liner or first casing 108, such as a surface casing, defined by lengths of tubing lining a first portion of the wellbore 102 extending from the surface 105 into the Earth. The first casing 108 is shown as extending only partially down the wellbore 102 and into the subterranean zone 106; however, the first casing 108 can extend further into the wellbore 102 or end further uphole in the wellbore 102 than what is shown schematically in FIG. 1. A first annulus 109, radially outward of the first casing 108 between the first casing 108 and an inner wall of the wellbore 102, is shown as filled with cement. The example well system 100 also includes a second liner or second casing 110 positioned radially inward from the first casing 108 and defined by lengths of tubing lining a second portion of the wellbore 102 that extends further downhole of the wellbore 102 than the first casing 108. The second casing 110 is shown as extending only partially down the wellbore 102 and into the second subterranean zone 107, with a remainder of the wellbore 102 shown as open-hole (for example, without a liner or casing); however, the second casing 110 can extend further into the wellbore 102 or end further uphole in the wellbore 102 than what is shown schematically in FIG. 1. A second annulus 111, radially outward of the second casing 110 and between the first casing 108 and the second casing 110, is shown as filled with cement. The second annulus 111 can be filled partly or completely with cement. In some instances, this second annulus 111 is a casing-casing annulus (CCA), for example, because it is an annulus between two tubular casings in a wellbore. While FIG. 1 shows the example well system 100 as including two casings (first casing 108 and second casing 110), the well system 100 can include more casings or fewer casings, such as one, three, four, or more casings. In some examples, the well system 100 excludes casings, and the wellbore 102 is at least partially or entirely open bore.

The wellhead 104 defines an attachment point for other equipment of the well system 100 to attach to the well 102. For example, the wellhead 104 can include a Christmas tree structure including valves used to regulate flow into or out of the wellbore 102, casing attachments such as casing spool outlets that connect to the casing annulus(es), a combination of these elements, or other structures incorporated in the wellhead 104. In the example well system 100 of FIG. 1, a well string 112 is shown as having been lowered from the wellhead 104 at the surface 105 into the wellbore 102. In some instances, the well string 112 is a series of jointed lengths of tubing coupled end-to-end or a continuous (or, not jointed) coiled tubing. The well string 112 can make up a work string, testing string, production string, drill string, or other well string used during the lifetime of the well system 100. The well string 112 can include a number of different well tools that can drill, test, produce, intervene, or otherwise engage the wellbore 102. For example, FIG. 1 shows the well string 112 as including a well tool 114 at a bottommost, downhole end of the well string 112.

The example well system 100 also includes a well treatment system 116 fluidly connected to the wellhead 104, for example, by a fluid conduit 118. The well treatment system 116 provides sealant material to the wellhead 104, which directs the sealant to a location within the well system 100. For example, components of the well system 100, such as the cement of the first annulus 109 or the cement of the second annulus 111, can include fluid loss openings that allow unwanted fluid migration within the wellbore 102, the annuluses, or other locations in the well system 100. The fluid loss openings can include cracks, fractures, perforations, or other openings that allow unwanted fluid flow or leaks. The well treatment system 116 provides sealant material to one or more of these fluid loss openings to seal, partially or completely, the one or more fluid loss openings to reduce or prevent fluid migration through the one or more fluid loss openings.

FIG. 2 is a schematic view of the example well treatment system 116, which can be used in the well system 100 of FIG. 1. The well treatment system 116 produces a sealant composition in gaseous form, and provides the gaseous sealant to a desired portion of a wellbore, such as wellbore 102. For example, referring to FIGS. 1 and 2, the example well treatment system 116 can provide a gaseous sealant to the wellhead 104, in particular, a casing spool side flange of the wellhead 104, and the wellhead 104 can direct the gaseous sealant to an annulus of the wellbore 102, such as the first annulus 109, the second annulus 111, or another annulus or CCA of the wellbore 102. Since the first annulus 109 and second annulus 111 are cemented, the gaseous sealant can be injected into one or more of these annuluses, can flow to and through any fluid loss openings in the cement of these annuluses, and can cool to a solid-phase or liquid-phase sealant to fill, plug, block, or otherwise seal the fluid loss openings in the cement. For example, a buildup of high pressure in the cemented annulus monitored by a pressure gauge at a casing spool outlet flange can signify the presence of micro-cracks formed in the cement. In response to this monitored high pressure, a sealant injection process can proceed to seal, partially or completely, the fluid communication channels in the cement in the annulus.

The example well treatment system 116 of FIG. 2 includes a heater 202, a compressor 204, and a purge assembly 206 fluidly connected to each other, and the fluid conduit 118 that fluidly connects the well treatment system 116 and allows flow of the sealant to the wellhead 104. The heater 202 includes a heating chamber 208 to heat the sealant to a gaseous phase. In some implementations, the heater 202 includes an electric heating chamber 208 that is sealed from atmosphere during a heating process of the sealant. In other implementations, the heater 202 can include a combustion-type heater or other non-electric heating chamber. However, in implementations where the example well treatment system 116 is part of a well system and may be exposed to hydrocarbons or other combustible materials present at a well system, combustion-type heaters can be dangerous, and electric-type heaters are preferred.

Prior to being heated in the heating chamber 208, the sealant may be in a solid phase, a liquid phase, or a combination of both, such as a hybrid-phase gel-type material. The solid-phase or liquid-phase sealant 212 is shown in FIG. 2 as disposed in the heating chamber 208 prior to phase-changing to a gaseous sealant. Examples of the sealant can vary, and the sealant can transition to gas phase in the heater 202 via vaporization or sublimation. In some implementations, the sealant is inert, in that it does not chemically react to steel, cement, or formation fluids including water or hydrocarbon. In certain implementations, the sealant can evaporate or sublimate at relatively low temperatures, such as between 250 degrees Celsius and 300 degrees Celsius, with a low change in boiling point with applied pressure. For example, the heated sealant in gaseous phase maintains its phase during injection and does not return to its original phase, such as a solid or liquid phase, while within the compressor 204 due to the pressure inside the compressor 204. In some examples, the sealant can include Kevlar fiber, tar, naphthalene, other chemicals or mixture of chemicals, or a combination of these.

The heater 202 heats the sealant in its heating chamber 208 to a temperature above the vaporization temperature or sublimation temperature of the sealant material to induce a phase transition of the sealant to its gas phase. With the sealant in gaseous phase, the well treatment system 116 can flow the sealant to and through the fluid loss opening(s) of a well system, and upon cooling of the sealant, the sealant can return to its initial solid phase, liquid phase, or hybrid phase while disposed within the fluid loss opening(s), thereby sealing (partially or completely) the fluid loss openings from fluid migration. The heating and cooling temperature of the sealant depends on the sealant boiling point temperature. In an example, if the sealant has a boiling and evaporating temperature of 250 degrees Celsius (° C.), the sealant should be heated to 300-350° C. in the heater 202 before being injected down into the cracks of the cement in the annulus. As the sealant travels through the cement cracks, the sealant will gradually lose heat and return to its original phase at the same boiling point of 250° C. In some examples, the sealant can be heated in the heater 202 to 50-100° C. greater than its boiling, evaporation, or sublimation temperature, then injected into the cemented annulus to fill fluid loss openings and channels created by micro-cracks. The sealant can then gradually cool down to below its boiling, evaporation, or sublimation temperature while residing in the fluid loss openings and channels, thereby sealing the fluid loss openings and channels. The seal created by the sealant can be a partial or complete pressure seal, partial or complete fluid seal, partial or complete blockage, or other type of seal. In some examples, the temperature of the wellbore and surrounding earth is much cooler than the injected gaseous sealant. Hence, the sealant cools down and returns to its solid or liquid phase after a cooling time. As more injection is performed, more solid or liquid sealant fills the cracks and blocks any further injection. Once the injection pressure reaches a predefined maximum level, the injection can cease. Cooling of the sealant from its gaseous phase to its original liquid phase or solid phase can occur naturally, as the temperature of the annulus is less than the vaporization or sublimation temperature of the sealant. The sealant is injected into the cement and takes up the space present in the cracks, leaks, or other fluid loss openings in the cement, and naturally cools down, which prompts the phase transition of the sealant back to its solid phase or liquid phase.

In some implementations, as depicted in FIG. 2, the compressor 204 pumps the gaseous sealant from the heater 202 toward the fluid loss openings of a well system. The compressor 204 is a gas compressor, and provides a controlled injection pressure of the gaseous sealant to the fluid conduit 118. The compressor 204 can pump the gaseous sealant to an annulus of the wellbore 102 via the fluid conduit 118 at a continuous pressure, in cycles of higher and lower pressures, or in another injection pattern.

In some instances, the well treatment system 116, wellhead 104, or both, includes a pressure sensor (not shown) to monitor a pressure in the first annulus 109, second annulus 111, wellbore 102, work string 112, or a combination of these. For example, in instances where the well treatment system 116 provides the gaseous sealant to the second annulus 111 (the CCA), the pressure sensor can monitor the pressure in the second annulus 111. Monitored data from the pressure sensor can be used to determine an injection pressure, an injection process cycle, a pressure testing cycle, or a combination of these. In some examples, as the well treatment system 116 provides gaseous sealant to the second annulus 111 in injection process cycles, a positive pressure test result from the pressure sensor can signify that no further sealant injection is possible, that the fluid loss openings in the cement of the second annulus 111 are sealed, or both.

As described earlier, cement in the first annulus 109, cement in the second annulus 111, or cement in both annuluses are prone to cracks or other wear that can allow fluid leakage and unwanted fluid migration through the cement. Sealant in the gaseous phase has a higher injection potential or permeability than sealant in a solid phase or liquid phase. Utilizing the well treatment system 116, the gaseous sealant can be introduced and injected into fluid loss openings at a higher injection potential and permeability than solid or liquid sealant, yet can still cool and transition phases to its original solid or liquid phase once the sealant is already disposed within the fluid loss openings.

In some implementations, prior to or upon completion of (or both) a heating and injection process of the sealant, the heating chamber 208 of the heater 202 is purged with the purge assembly 206. The example purge assembly 206 of FIG. 2 includes one or more inert gas cylinders 210 (five shown), with each inert gas cylinder 210 having a controlled valve that controls an inert gas supply from the cylinders 210 to the heating chamber 208 of the heater 202. The inert gas supplied to the heating chamber 208 purges the heating chamber 208, for example, reduce the risk of or prevent undesired combustion of any residual material in the heating chamber 208 at high temperatures. In some examples, before the heating process of a sealant, the inert gas is used to push all of the air out of the heating chamber 208 through a venting valve (not shown) in the fluid conduit 118 and released to atmosphere, or directed to a separate purge storage tank. During the heating process, the inert gas can be used to purge the heating chamber 208 and push the gaseous sealant 212 inside the chamber 208 into the compressor 204 to be injected into the casing annulus. In some implementations, the heating and purging and injection process is repeated in cycles until the desired pressure lock up in the annulus is achieved and no more injection is possible. The inert gas cylinders 210 can include an inert gas supply of nitrogen, helium, or other inert gases.

FIG. 3 is a flowchart describing an example method 300 for treating a well, for example, performed by the example well treatment system 116 of FIG. 2. At 302, a sealant heated to a gaseous phase flows to cement disposed in an annulus of a wellbore. The annulus is formed between a casing installed in the wellbore and a cylindrical wall radially outward of the casing, where the cement includes a fluid loss opening formed over time in the cement. At 304, the sealant in gaseous phase flows through the fluid loss opening in the cement of the wellbore. At 306, the sealant in the gaseous phase cools into a phase transition of the sealant. The phase transition includes at least one of a deposition of the sealant from the gaseous phase to a solid phase or a condensation of the sealant from the gaseous phase to a liquid phase. At 308, the sealant seals the fluid loss opening in response to cooling the sealant.

FIG. 4 is a flowchart describing an example method 400 for treating a well, for example, performed by the example well treatment system 116 of FIG. 2. At 402, a sealing composition in a gaseous phase flows through a fluid loss opening in a well. At 404, the sealing composition cools into a phase transition of the sealing composition. The phase transition includes at least one of a deposition of the sealing composition from the gaseous phase to a solid phase or a condensation of the sealing composition from the gaseous phase to a liquid phase. At 406, the sealing composition seals the fluid loss opening in response to cooling the sealing composition into the phase transition of the sealing composition.

A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure. 

1. A method for treating a well, the method comprising: injecting a sealant in a gaseous phase into cement that is within and that seals an annulus of a wellbore proximate to a wellhead of the wellbore, the annulus formed between a casing installed in the wellbore and a cylindrical wall radially outward of the casing, where the cement disposed in the annulus includes a fluid loss opening formed over time in the cement; flowing the sealant in gaseous phase through the fluid loss opening in the cement of the annulus; in response to flowing the sealant through the fluid loss opening, cooling the sealant in the gaseous phase into a phase transition of the sealant, the phase transition comprising at least one of a deposition of the sealant from the gaseous phase to a solid phase or a condensation of the sealant from the gaseous phase to a liquid phase; and sealing the fluid loss opening with the sealant in response to cooling the sealant.
 2. The method of claim 1, comprising heating the sealant in a heating chamber and converting the sealant to the gaseous phase.
 3. The method of claim 2, wherein converting the sealant to the gaseous phase comprises at least one of a sublimation of the sealant from solid phase to gaseous phase or an evaporation of the sealant from liquid phase to gaseous phase.
 4. The method of claim 2, wherein the heating chamber comprises an electric heating chamber, and heating the sealant comprises heating the sealant in the electric heating chamber.
 5. The method of claim 2, further comprising purging the heating chamber using inert gas chambers fluidly connected to the heating chamber.
 6. The method of claim 1, wherein injecting the sealant into the cement disposed in the annulus of the wellbore comprises pumping the sealant into the cement with a compressor.
 7. The method of claim 1, wherein injecting the sealant into the cement disposed in the annulus of the wellbore comprises continuously flowing the sealant in the gaseous phase into the cement until a positive pressure test of the annulus occurs.
 8. The method of claim 1, wherein injecting the sealant into the cement comprises injecting the sealant in the gaseous phase downhole through the cement in the annulus from a tophole surface of the wellbore.
 9. The method of claim 1, wherein the fluid loss opening comprises a crack in the cement of the wellbore, and sealing the fluid loss opening with the sealant comprises pressure sealing the crack in the cement of the wellbore with the sealant.
 10. The method of claim 1, wherein the sealant in gaseous phase comprises an inert gas.
 11. A well treatment system for treating a well, the well treatment system comprising: a heating chamber fluidly connected to an annulus of a wellbore proximate to a wellhead of the wellbore, the annulus sealed by cement, the heating chamber to heat a sealant to a gaseous phase and provide the sealant in gaseous phase to the cement that is within and that seals the annulus; the sealant in gaseous phase to engage a fluid loss opening in the cement and, upon cooling the sealant, transition phases from the gaseous phase to at least one of a liquid phase or a solid phase and plug the fluid loss opening; and a gas compressor to flow the sealant in the gaseous phase from the heating chamber to the annulus of the wellbore.
 12. (canceled)
 13. The well treatment system of claim 11, wherein the wellhead comprises a casing spool flange to receive a flow of the sealant from the heating chamber and direct the flow of sealant into the annulus of the wellbore.
 14. The well treatment system of claim 11, where the fluid loss opening in the cement disposed in the annulus of the wellbore comprises a crack in the cement.
 15. The well treatment system of claim 14, where the crack in the cement of the annulus comprises a micro-crack in the cement.
 16. The well treatment system of claim 11, wherein the heating chamber comprises an electric heating chamber.
 17. The well treatment system of claim 11, comprising inert gas chambers fluidly connected to the heating chamber to purge the heating chamber.
 18. The well treatment system of claim 11, where the annulus is formed between a casing installed in the wellbore and a cylindrical wall radially outward of the casing.
 19. The well treatment system of claim 18, where the cylindrical wall comprises a second casing installed in the wellbore radially outward from the first-mentioned casing or an inner wall of the wellbore.
 20. A method for treating a well, comprising: heating a sealing composition in a heating chamber to a gaseous phase; flowing the sealing composition in the gaseous phase from the heating chamber to an annulus of a wellbore formed between a casing installed in the wellbore and a cylindrical wall of the wellbore, the annulus sealed with cement disposed in the annulus, wherein the cement includes a fluid loss opening formed over time in the cement; injecting the sealing composition in the gaseous phase into the cement and through a fluid loss opening in the cement disposed in the annulus; cooling the sealing composition into a phase transition of the sealing composition, the phase transition comprising at least one of a deposition of the sealing composition from the gaseous phase to a solid phase or a condensation of the sealing composition from the gaseous phase to a liquid phase; and in response to cooling the sealing composition into the phase transition of the sealing composition, sealing the fluid loss opening with the sealing composition. 21-23. (canceled) 